Retrievable well packer apparatus



April 8, 1969 D.IE. YOUNG 3,437,136

RETRIEVABLE WELL PACKER APPARATUS Filed Dec. 28. 1967 Sheet or 4 flaw/a ff oung INVENTOR.

AJ'I'ORIVE V A ril 3, 1 969 D. E. YOUNG 3,437,136

RETRIEVABLE WELL PAGKER APPARATUS Filed Dec. 28. 1967 Sheet 2 of 4 -i- ZZLQ 3 1 Dawn 6 ou/79' IN V EN TOR. 2.9

3/ 'BY I April 8, 1969 D. E. YOUNG 3,437,136

RETRIEVABLE WELL P'ACKER APPARATUS Filed Dec. 28, 1967 Sheet 3 of an 84 36 A .Da w a 5. V0 any IN VEN'TOR BY jaw: 7

ATTORNEY April 8, 1969 D. E. YOUNG 3,437,136

RETRIEVABLE WELL PACKER APPARATUS Filed Dec. 28, 1967 Sheet 4 of4 .fia V/ a 1 o any INVENTOR.

ATTORNEK United States Patent 3,437,136 RETRIEVABLE WELL PACKER APPARATUS David E. Young, 5318 Holley, Bellaire, Tex. 77401 Continuation-impart of application Ser. No. 578,802, Sept. 12, 1966. This application Dec. 28, 1967, Ser. No. 695,829

Int. Cl. E21b 23/00, 33/12, 33/13 US. Cl. 166120 7 Claims ABSTRACT OF THE DISCLOSURE sive to fluid pressure differentials for exerting force on i said expander means in a direction to maintain the said slip means anchored against movement in the opposite longitudinal direction in a well.

This application is a continuation-in-part of application Ser. No. 578,802, filed Sept. 12, 1966, now abandoned.

This invention relates generally to well tools, and more specifically to well tools used for packing off or isolating well bore zones.

To conduct testing, remedial, stimulation or production operations in a particular zone in a well, the zone can be isolated by well tools which can be positioned in the well bore below and above the zone. The lower tool, commonly called a bridge plug, functions to seal off the entire cross-section of the well bore to isolate the zone from fluids at their hydrostatic pressures which are below the zone. The upper tool, commonly called a packer, functions to seal off the annulus between a tubing string attached to the packer and the well casing to isolate the zone from fluids at their hydrostatic pressures which are above the zone. The tubing string provides a means of access to the isolated zone for fluid flow, testing tools, or for wireline or other instruments which can be lowered therethrough.

For the lower tool, two general types of bridge plugs have been used. First, a so-called permanent bridge plug can be used which has opposed slips and a packing element and once set can only be removed by destruction, that is to say, by drilling it away with a drill bit or milling tool. Second, a so-called retrievable bridge plug can be used which will provide a pressure bridge the same as the permanent-type plug but which can be retrieved from the well after use. This type of bridge plug has been popular in the industry for the obviou reason that the tool can be retrieved to the surface without requiring a drilling operation.

Very commonly, a bridge plug is required to hold its position within the well casing even though the pressure differentials acting on it are reversed in direction during a typical operation. For example, if cement slurry is squeezed through casing perforations and into earth formations adjacent the isolated zone, the pressure of fluids above the bridge plug may exceed the pressure of the fluids below it. The pressure difference is effective as a force tending to move the plug downwardly. Accordingly, a typical bridge plug has anchors which hold the tool against downward movement. Then the zone may be swabbed tested, e.g., fluids in the tubing string are lifted out and removed to reduce the hydrostatic pressure in the isolated 3,437,136 Patented Apr. 8, 1969 zone to a value lower than natural formation fluid pressures to induce formation fluid flow into the well bore. When this is done, the pressures of fluids below the bridge plug may exceed the pressures of fluids above it and the pressure difference acts as a force tending to move the bridge plug upwardly. Accordingly, a typical bridge plug has anchors which hold it, against upward movement.

Such pressure reversals may also act on the packer which is positioned in the well casing above the zone. During a cement squeeze, fluid pressures below the packer will tend to move it upwardly while during swab testing, fluid pressure on the well annulus above the packer will exert downward forces on it. Accordingly, a packer may have upper and lower anchor devices to prevent its movement in either direction.

The need for opposed sets of anchors to hold against up or down movement has made such tools complex in structure and operation. Added complexity increases the probabilities of malfunction and the cost of maintenance.

The present invention provides a well tool which is illustrated in a retrievable bridge plug form which has only a single anchor and a single expander, yet which will not move up or down in a well conduit even though pressure differences acting on the plug are reversed from down to up, or vice versa. The present invention is therefore less complex in structure and operation and relatively free from malfunction and maintenance problems.

Briefly, the present invention may be summarized from a conceptual standpoint as an apparatus comprising a body member with packing means thereon for packing off a well bore. Expander means and normally retracted expansible slip means which can be expanded by the expander means into gripping engagement with a well conduit are provided for anchoring the apparatus against movement in the well conduit. Hydraulic means including piston members which are arranged to have the capability of movement relatively toward each other after the slip means are expanded are provided for exerting force on said expander means in response to high fluid pressure below said packing means, in a direction to maintain the gripping engagement of said slip means.

The novel features of the present invention are set forth with particularity in the appended claims. The invention, together with its objects and advantages, may be best understood by way of illustration and example of embodiments thereof when taken in conjunction with the following drawings in which:

FIGURE 1 is a schematic view of a well having well tools positioned therein for isolating a zone in which operations are to be performed;

FIGURES 2A is a sectional view of the upper portion of an apparatus in accordance with the present invention with parts in relative positions for longitudinal movement in a well conduit;

FIGURE 2B is a view similar to FIGURE 2A showing the lower portion of the apparatus of the present invention and forms a lower continuation of FIGURE 2A;

FIGURE 3 is a cross-section taken on line 3-3 of FIGURE 2A;

FIGURE 4 is a cross-section taken on line 44 of FIGURE 2B;

FIGURE 5A is a sectional view similar to FIGURE 2A but with parts in relative positions they occupy when the apparatus is set in the well conduit;

FIGURE 5B is the lower continuation of FIGURE 5A;

FIGURE 6 is a fragmentary view of an alternative embodiment of an apparatus which embodies principles of the present invention; and

FIGURES 7A and 7B are longitudinal sectional views, with portions in side elevation, of another embodiment 3 of the present invention, FIGURE 7B forming a lower continuation of FIGURE 7A.

Referring initially to FIGURE 1, a typical well bore B is lined with a conduit or casing C and traverses the earth formation F to be tested, treated, or stimulated. A zone Z of the well bore B is isolated by a packer P1 at the zones upper end and a bridge plug P-2 at the zones lower end. A tubing string T i connected to the packer P1 for access to the zone Z from the earths surface. Perforations S may extend through the casing C and into the formation F for fluid communication between the zone Z and the formation F. The packer P1 can be any conventional device normally used in the art such as that shown in US. Patent No. 3,020,959 or it can embody the concepts of the present invention as will hereinafter be made apparent with respect to a bridge plug.

Referring now to FIGURES 2A and 2B for details of the tool P-2 characterized a a retrievable bridge plug, apparatus in accordance with the present invention includes a generally tubular body member 10 extending throughout the length of the well tool P-2. The body member 10 has a central bore 11 which is opened at its lower end by several side ports 12. The upper end of the body member is closed by a threadedly attached connector head 13 having J-slots 14 or the like in its periphery for connecting to a conventional retrievable bridge plug overshot (FIGURE 1). An O-ring or other sealing mean can make the threaded connection fluid tight.

A plurality of bypass ports 17 extend laterally through the wall of the body member below the connector head 13. Sealing elements 18 and 19 are received in annular grooves above and below the ports 17. A sleeve valve 20 is slidably disposed on the body member 10 adjacent the ports 17 and is movable between a lower position as shown in FIGURE 2A where the bypass ports 17 are open, to an upper position where the upper end of the sleeve valve 20 abuts the lower end 21 of the connector head 13. In the upper position, the sleeve valve 20 spans the ports 17 and, in combination with the sealing elements 18 and 19, functions to block fluid flow therethrough. A plurality of spring fingers 22 extend from the lower end of the sleeve valve 20 and have enlarged head portions 23 which are sized to engage an upwardly facing shoulder 24 formed on the body member 10 when the sleeve valve is in its upper position. A predetermined downward force is required to cause outward flexure of the spring fingers 22 and downward movement of the sleeve valve 20. This predetermined resistance to downward movement holds the sleeve valve 20 in its upper, port-closing position.

An intermediate portion of the body member 10 is enlarged to provide a downwardly facing shoulder or abutment 27. The abutment 27 has a bore 28 therein which is sized to slidably receive an annular compression sleeve 29 therein. The lower end of the compression sleeve 29 has an outwardly extending annular flange 30 to provide an upwardly facing abutment. An elastomeric packing means 31 is mounted around the compression sleeve 29 with its ends engaging the abutments 27 and 30. Typical O-ring seals 32 and 33 are positioned between the upper abutment 27 and the compression sleeve 29 and between the compression sleeve 29 and the body 10, respectively, to prevent fluid leakage therebetween.

A hydraulically operable piston member 36 is slidably received on the body member 10 below the compression sleeve 29 and the packing means 31. An expander cone 37 is attached to the piston member 36 by an annular sleeve 38 which is threadedly coupled to the piston member. A seal element 39 seals the threaded connection 40 and another seal element 41 seals between the inner periphery of the piston member 36 and an outer surface of the body member 10.

The expander sleeve 38 forms an internal annular recess 43 which extends from the upper face 44 in the expander cone 37 to the lower face 45 of the attached piston member 36. The recess 43 slidably receives an annular flange 46 which may be an integral part of the body member 10. A suitable sealing element 47 seals between the outer periphery of the flange 46 and the inner periphery of the sleeve 38 so that a chamber 48 is provided between the upper face of the flange 46 and the lower face 45 of the piston member 36. It will be appreciated that the chamber 48 is variable in volume inasmuch as the piston member 36 and the body member 10 can move relative to one another.

A tubular cage member 50 is movably mounted on the lower end portion of the body member 10 with its lower end normally engaging an upwardly facing shoulder 51 on the body member. A plurality of radially directed, circumferentially spaced recesses 52 in the cage member 50 receive conventional drag blocks 53 which are urged outwardly by springs 54 to engage the well conduit wall, outward movement of the blocks being limited by tangs 55 and 56. The drag blocks 53 function to retard rotational and longitudinal movement of the cage member 50 within the well conduit C. For the purpose of controlling longitudinal relative movement between the cage member 50 and the body member 10, upper and lower segmental ratchet nuts 57, 58, respectively, are positioned within internal annular recesses 59 and 60 in the cage member 50. The ratchet nuts 59 and 58 are commonly called dizzy nuts and have internal buttress form teeth which can be selectively engaged with companion external threads 62 and 63 on the body member. The upper body threads 62 are right-hand threads formed to face downwardly so that when they are engaged with the upper ratchet nut 57, the cage member 50 cannot move upwardly relative to the body member 10. However, the body teeth 62 can be released from the ratchet nut 57 by right-hand rotation. The lower body threads 63 are left-hand threads formed to face upwardly so that when they are engaged with the lower ratchet nut 58, the body member 10 cannot move upwardly relative to the carriage member. As in the case of the upper body teeth 62, however, the lower body teeth 63 can be released from the lower ratchet nut 58 by righthand rotation of the body. Due to the form of the teeth 62 and 63, it will be appreciated that the upper body teeth 62 can be ratchetted upwardly through the upper ratchet nut 57 and the lower body teeth 63 can be ratchetted downwardly through the lower ratchet nut 58. Projections 64 and 65 on the cage member 50 engage between segments of the ratchet nuts 57 and 58 as shown in FIGURES 2B and 4 so that the ratchet nuts cannot rotate relative to the cage member as the body member 10 is rotated. Resilient bands 66 and 66 can be positioned within grooves 67 (FIGURE 4) around the nuts 57 and 58 and function to permit radial expansion of the nuts as the body teeth are ratchetted therethrough, while continuously urging inward contraction.

A plurality of slip segments 70 are carried by the upper end of the cage member 50. The slip segments 70 can have external wickers or teeth 71 on their peripheries which are adapted to bite into and grip the well conduit wall. Also, the slip segments 70 can have inner inclined surfaces 72 which diverge upward and outwardly of the body member 10 and are complementary to outer inclined surfaces 73 on the expander cone 37 in a manner whereby when the expander cone 37 is brought into engagement with the slip segments 70, downward movement of the expander cone 37 relative to the slip segments 70 will cause outward shifting of the slip segments 70 into positions of engagement with the well conduit wall. The lower end of each slip segment 70 can be provided with a keyed tongue 74 which engages in an inclined groove 75 in the cage member 50 so that the slip segments 70 can be readily moved outwardly. cantilevered spring members 76 can be attached to the outer surfaces of the cage member 50 with their free ends pressing the slip segments 70 toward retracted positions.

That portion of the body member 10 adjacent the packing element 31 has at least one fluid passageway 80 as shown in FIGURES 2 and 3 extending longitudinally from ports 81 and 82 which are in communication with the well annulus above the packing element 31, to port means 83 which is in communication with the lower face 45 of the piston member 36. Thus, it will be apparent that the lower face 45 of the piston member 36 is subject to fluid pressures in the well annulus above the packing element 31 while the upper face 84 of the piston member 36 is subject to fluid pressures in the well annulus below the packing element 31. Accordingly, whenever the packing element is expanded into sealing engagement with the casing and fluid pressures below the packing element 31 exceed those of fluids above it, the pressure differential will act on the piston differential area A as downwardly directed force on the expander cone 37 which is translated to outward force on the slip segments 70 by virtue of the coaction of the inclined surfaces 72 and 73. Therefore, the hydraulic system of the present invention responds to an upwardly acting pressure differential to maintain the set condition of the slip elements 70 and thereby prevent upward movement of the tool. On the other hand, when a downwardly acting pressure differential is exerted on the tool, the higher pressure is communicated into the chamber 48 to act upwardly on the lower face of the piston member 36. However, the pressure is also acting downwardly on the cross-sectional areas of the expanded packing element 31, the compres sion sleeve 29, and on the body member 10 so that the net force on the expander cone 37 is directed downwardly to force the slip segments 70 outwardly.

Another embodiment of the hydraulic system of the present invention is shown in FIGURE 6. An annular floating piston member 86 is slidably received in the recess 43 above the expander cone 37. Suitable seals, for example, O-rings 87 and 88, seal between the inner periphery of the piston member 86 and the outer surface of the body member 10, and between the outer periphery of the piston member 86 and the inner surface of the sleeve 38, respectively. An annular shoulder 89 on the body member 10 limits upward movement of the piston member 86 within the recess 43 and downward movement is stopped by the upper surface 44 of the expander cone 37. If the fluid pressures above the packing element 31 are lower than pressures below it, the floating piston member 86 will engage the shoulder 89 on the body member 10. The higher fluid pressures below the packing element 31 will exert downward force on the piston member 36 which is attached to the expander cone 37 as in the case of the apparatus shown in FIGURES A and 5B, thereby exerting holding force on the slip segments 70. Moreover, if the pressures above the packing element 31 are higher, the floating piston member 86 will move downwardly to engage the upper face 44 of the expander cone 37, thereby transmitting force due to such pressures directly to the expander cone 37. Thus, the net force on the expander cone 37 is directed downwardly as in the case of the embodiment shown in FIGURES 5A and 5B to act on slips 70 in anchoring positions.

In the operation of the apparatus thus far described, the parts can be assembled as shown in FIGURES 2A and 2B and lowered in the well conduit C to a location where it is desired to form a pressure bridge, for example, the location of the tool P2 in FIGURE 1. During lowering, the tubing string T is connected to the connector head 13 by an overshot running tool 0 and the sleeve valve 20 is in its lower position where the bypass ports 17 are open. Thus, fluids in the well bore can bypass through the tool via the lower ports 12, the body passageway 11 and the bypass ports 17, as well as around the packing element "31. In view of the ample bypass area, the well tool P2 can be quickly lowered to setting depth.

During lowering, the upper ratchet nut 57 is i engagement with the upper body threads 62 to prevent upward movement of the cage member 50 relative to the body member 10. The slip segments are pressed inwardly by the springs 76 and, being attached to the cage member, cannot move upwardly to be shifted outwardly by the expander cone 37.

At the setting depth, the well tool P2 is halted and the body member 10 is torqued or turned several turns to the right by manipulation of the tubing string T to release the upper ratchet nut 57 from the upper body threads 62. The cage member 50 will not rotate due to the frictional engagement of the drag blocks 53 with the Well conduit wall. Release of the upper ratchet nut '57 permits downward movement of the body member 10 relative to the cage member 50 to move the expander cone 37 behind the slip segments 70, thereby shifting the slip segments 70 into gripping engagement with the well conduit wall.

When the slip teeth 71 are firmly engaged, the expander cone 37 is supported against further downward movement and the piston member 36 prevents further downward movement of the compression sleeve 29. Accordingly, the weigh-t of the running-in string -T can be imposed on the body member 10 to compress the packing element 31 between the upper and lower abutments 27, 30 and effect its expansion into sealing engagement with the well conduit wall as shown in FIGURES 5A and 5B.

As the body member 10 moves downwardly relative to the cage member 50, the lower body threads 63 can ratchet through the lower ratchet nut 58 which will trap the body member in the lowermost position to which it is moved to lock the compression energy in the packing element 31. The running tool 0 can now be manipulated to a release posit-ion relative to the connector head 13 and upward movement of the overshot will automatically move the sleeve valve 20 to its upper, port closing position with the spring fingers 22 engaging the shoulder 24 on the body member v10. The crosssectional areas encompassed by the seal elements 18 and 19 can be made to be substantially the same so that the sleeve valve 20 is pressure balanced and will not move responsive to differences in fluid pressures below and above the well tool P2.

The tubing string T is then lifted to position the upper packer P-l above the formation F and the upper packer is set. If a cement squeeze or other pressure operation is conducted in the zone Z above the Well tool P2, the net forces on the expanded cone 37 are directed downwardly, as previously described, setting the slip segments 70 even tighter against the well conduit to prevent downward movement. Moreover, if the pressures of the fluids above the well tool P2 are reduced to values lower tha those below the tool, upward force on the body member 10 is transmitted by the cage member 50 to the slip elements 70 which are gripping the well conduit wall. The lower pressures are communicated via the passageway to the chamber 48 below the piston member 36. The higher fluid pressures below the packing element 31 act on the upper face 84 of the piston member 36 and the pressure difference will act on the annular cross-sectional area A as downward force on the expander cone 37 to hold the slip segments 70 firmly engaged with the well conduit wall, thereby preventing upward movement.

When it is desired to either retrieve the well tool P2 to the surface or move to another setting position, the upper packer Pl is released and the tubing string T lowered to engage the running tool 0 with the connector head 13. The sleeve valve 20 is automatically moved to its lower position where the bypass ports 17 are open to equalized fluid pressures across the packing element 31 and across the cone holding piston member 36. The body member 10 is then rotated several turns to the right to release the lower ratchet nut 58 from engagement with the lower body threads '63, thereby releasing the body member 10 for upward movement relative to the cage member 50. As the body member is pulled upwardly, the compression on the packing element 3-1 is released and it will inherently retract. The body flange 46 will engage the piston member 36 to pull the expander cone 37 from behind the slip segments 70, thereby permitting their retraction. As the body member 10 reaches the upper limit of its travel relative to the cage member 50, the upper body threads 62 will ratchet through the upper ratchet nut 57 to again lock the cage member against upward movement relative to the body member 10, downward movement thereof being prevented by the shoulder 51 on the body member 10. The well tool P-2 is then free for shifting in the well conduit C.

Another embodiment of the present invention is illustrated in FIGURES 7A and 7B. A central mandrel or body extends throughout the length of the tool and has a connector head 101 at its upper end, the connector head being provided with a slot system 102 for coaction with the running tool 0. A bypass valve sleeve 10?: is arranged for downward and upward movement to respectively open and close bypass ports 104 in the wall of the mandrel.

A cage member 106 is movably mounted on the lower end portion of the mandrel 100 above a gauge ring stop 107. The cage member 106 carries circumferentially spaced drag blocks 108 which are urged outwardly by coil springs 109. A plurality of wickered slip elements 1 10 can be pivotally coupled to the upper end of the cage member 106 by reins 111 or the like, and are arranged for lateral movement between retracted and expanded positions. An expander cone 113 has outer inclined surfaces 114 which engage inner inclined surfaces 115 on the slip elements 110, and the slip elements can be slidably coupled to the expander cone by a conventional dovetail tongue and groove connection 116.

A clutch assembly is provided for controlling relative longitudinal movement between the cage member 106 and the mandrel 100. The clutch assembly includes a segmental clutch nut v117 which is received within an internal annular recess 118 in the cage member, each of the nut segments 119 being secured against rotation relative to the cage member by lugs 120 which engage in peripheral slots in the segments. Upper and lower band springs 121 and .122 permit lateral movement of the nut segments while continuously urging the segments toward contracted positions around the mandrel 100. Each nut segment 119 can have upper left-hand threads 123 and lower right-hand threads 124 which are cooperable with companion threads v125 and 126 on the mandrel to secure the mandrel relative to the cage member in spaced longitudinal positions. An inwardly biased stop lug 127 can initially engage within a shouldered recess 128 in the mandrel to prevent counter-clockwise rotation of the cage member 106 relative to the mandrel during lowering, thereby preventing rotational locking of the lower end surface of the cage members against the upper face of the gauge stop ring 107.

A packing element 130 is mounted around a compression sleeve 131 which has an enlarged upper section and an upper annular abutment .132 engaging the upper end of the packing element. The enlarged upper section of the sleeve 131 can have an internal annular recess 133 which receives an external annular flange 134 on the mandrel 100 in order to rotatively couple the sleeve and mandrel together. If desired, bearing rings 135 can be located between the flange 134 and the sleeve shoulder 136 to reduce frictional resistance to rotation of the mandrel 100 within the sleeve 131 under high load conditions.

The bore of the sleeve 131 can be enlarged relative to the outer diameter of the mandrel 100 to provide an annular passageway 137. One or more longitudinal grooves 138 can be cut in the flange 134 to continue the passageway 137 through the flange. An outer housing member 139 can be threadedly secured to the upper end portion of the compression sleeve 131, the housing member having a downwardly extending skirt 140 as well as an inwardly extending shoulder section 142 which is appropriately sealed against the external surface of the mandrel. An inner housing member 142 is located between the outer member 139 and the mandrel 100, the inner member 142 having an upwardly extending skirt 143 and an outwardly extending shoulder section .1 44 which is sealed against the outer housing member 139. The inner member is provided with upper ports 145 which, together with lower ports 146 in the outer housing member 139, form a somewhat tortuous flow path to communicate the passageway 137 with the well annulus above the packing element .130. The annular portion 147 of the path forms a substantial dead space within whichwell fluids can move without entering the passageway 137 in order to protect various working parts of the present invention from foreign matter or debris in a well.

A lower abutment ring 150 is arranged for sliding movement on the compression sleeve 131 and for advancement relatively toward the upper abutment 132 during compression and expansion of the packing element 130. In similar arrangement to the previously described embodiment of the present invention, an annular piston member 151 is sealingly slidable on the lower end portion .152 of the compression sleeve 131 and is connected by a force transmitting piston sleeve 153 to the expander cone 113. The piston member 151 can have an upwardly extending portion 154 with internal splines 155 or the like which are cooperable with a spline shoulder 156 on the compression sleeve 131 to corotatively and slidably couple the piston member to the compression sleeve. Moreover, an inwardly extending flange 157 can be provided which engages above the spline shoulder 156 to limit downward movement of the lower abutment 150 and the piston member 151 along the compression sleeve. The flange 157 supports the lower abutment ring 151, and radially extetnding lugs .158, which engage in appropriate flange detents, can be provided to prevent relative rotation.

In similar arrangement to the modified form of the first described embodiment shown in FIGURE 6, the mandrel 100 can have an outwardly extending annular stop shoulder 160 which limits upward movement of a floating piston member 161 which is slidable between the mandrel 100 and the piston sleeve 153. The piston member 16.1 has inner and outer seal rings 162 and 163 which respectively seal against the outer periphery of the mandrel 100 and the inner periphery of the piston sleeve 153. The upper piston member 151 is sealed against the outer periphery of the compression sleeve portion 152 by a suitable seal ring 164, and fluid leakage through the threaded connection 165 between the piston member and the piston sleeve is prevented by a seal ring 166.

The lowermost end surface of the compression sleeve portion 152 can be made to terminate just above the upper surface of the stop shoulder 160 in order to provide free communication between the pasageway 137 and the chamber 167 formed between the piston members 151 and 161. Thus it will be appreciated that fluid pressures in the well bore above the packing element 130 can act on the opposed faces of the piston members 151 and 161, while fluid pressures in the well annulus below the packing element 130 can act downwardly on the upper piston member 15.1 and upwardly on the floating piston member 161. The effective pressure area of the upper piston member 151 may be considered as the cross-sectional area between the inner periphery of the piston sleeve .153 and the outer periphery of the compression sleeve portion 152. Thus, a fluid pressure differential will act on this piston area as longitudinal force which will be transmitted by the piston sleeve 153 to the expander cone 1.13.

The embodiment of the present invention shown in FIGURES 7A and 7B operates in similar fashion to the first described embodiment. Thus, at setting depth in the well conduit, the mandrel 110 is lowered while rotating to the right in order to release the clutch nut threads 124- from the lower mandrel threads 126 and thus unlock the cage member 106 from the mandrel. Of course the cage member .106 will not rotate due to frictional engagement of the drag blocks 108 with the well conduit wall. Further lowering of the mandrel 100 without rotation will advance the expander cone 113 toward the slip elements 110 until the cone expands the slip elements into gripping and supporting engagement with the conduit. When the wickers of the slip elements 110 grip the wall, the expander cone 113 is supported against further downward movement so that the weight of the running-in string T can be imposed upon the mandrel 100 in order to advance the upper abutment 132 toward the lower abutment 150 and thereby compress and expand the packing element 130 into sealing egagement with the well conduit. The upper mandrel threads 125 can ratchet downwardly through the nut segments 119 and the upper segment teeth 123 will grip the upper mandrel threads 125 to trap the mandrel in the lowermost position to which it is moved, thereby trapping compression loading in the packing element 130. Appropriate manipulation of the running tool can then be undertaken in order to release the running-in string T from the connector head 101 and to move the bypass valve sleeve 103 upwardly to closed position. It will be appreciated that the tool now completely bridges the well bore against fluid flow in either direction.

In response to high pressure from above, the slip elements 110 are set even tighter against the casing to prevent downward movement of the tool. In response to high pressure from below the tool, the unique slip-holding feature of the present invention comes into play to prevent upward movement. The lower fluid pressure from above is communicated via the ports 146 and 145 and the passageway 137 to act on the lower face of the upper piston member 151. The high pressure from below can cause the floating piston member 161 to shift upwardly where its movement is stopped by the mandrel shoulder 160. Accordingly, downward force is developed on the upper piston member 151 which is equal to the product of the pressure differential times the effective pressure area of the piston member 151. -By virtue of the fact that the present invention is structurally arranged whereby the upper piston member 151 has the capability of downward movement relative to the lower piston member 161 and the mandrel 100 after the slip elements 110 are set, this force is transmitted by the piston sleeve 153 to the expander cone 113 and translated to outward force on the slip elements 110 due to the inclined surfaces 114 and 115 therebetween. Upward force on the mandrel 100 is transmitted through the cage member 106 to the slip elements 110 which are being held against upward movement by outward pressure from the expander cone 113. Thus it will be apparent that high pressure from below the tool is utilized to develop holding force on the slip elements 110 to maintain their teeth firmly embedded in the well casing wall, the holding force being proportionately related to the pressure differential. Consequently, the tool will not move upwardly in the casing, and, in sum, will not move in either direction in the casing in response to high pressure from above or below.

The alternative embodiment of the present invention can be retrieved from the well or moved to another setting position in the same manner as the first described embodiment. The running tool 0 connected to the lower end of the running-in string T is lowered over the connector head 101 and engaged therewith. This manipulation will move the valve sleeve 103 downwardly to open position in a typical manner so that pressures on the tool are equalized. Right-hand rotation coupled with a slight upward strain on the running-in string will effect rotation of the mandrel relative to the cage member 106 and release of the upper mandrel threads 125 from the nut segments 119. The mandrel 100 can be readily rotated through the compression sleeve 131 due to the bearing rings 135. Then upward movement of the mandrel 100 will permit relaxation and retraction of the packing element 130, along with retraction and release of the slip elements When the mandrel 100 has been moved upwardly to its original running-in relative position, the lower mandrel threads 126 will have ratcheted back into engagement with the nut segment threads 124 to prevent upward movement of the cage member 106 toward the expander cone 113. The gauge ring stop 107 will prevent downward movement of the cage member 106 relative to the mandrel. Thus, the various parts of the present invention are retained in retracted position for longitudinal movement in the well casing.

A new and improved well tool has been disclosed which has only a single anchor means and a single expander means, yet which will not move up or down in a well conduit responsive to fluid pressures from above or below. The well tool is simple in operation and elfective to pack off the cross-section of a well conduit. It will be appreciated that although the present invention has been illustrated in connection with a bridge plug, the concepts involved are applicable to other well tools such as squeeze packers and production tools. Since certain modifications or changes may be made without departing from the inventive concepts involved, it is intended that all matter contained in the foregoing description or shown in the attached drawings shall be interpreted as illustrative and not in a limiting sense.

What is claimed is:

1. In a well packer for packing off the cross section of a well conduit, the combination comprising: a tubular body member; a sleeve member slidable on said body member, said sleeve member having an upwardly facing abutment; an elastomeric packing means mounted around said sleeve member and adapted to seal between said sleeve member and a surrounding well conduit wall; seal means between said sleeve member and said body member; a downwardly facing abutment on said body member movable by said body member relatively toward said upwardly facing abutment to compress said packing means and expand it against a well conduit wall, said sleeve member having upper and lower oppositely facing surfaces subject to fluid pressure respectively above and below said packing means; slip means expandable outwardly of said body member into gripping engagement with a well conduit wall; expander means intermediate said slip means and said packing means and movable downwardly relative to said slip means for expanding said slip means outwardly; hydraulically operable means connected to said expander means and having an upper surface exposed to fluids in the well bore below said packing means; means on said body member forming a chamber with said hydraulically operable means, said hydraulically operable means having a lower surface exposed to fluid in said chamber; passage means for communicating the pressure of fluids in the well bore above said packing means with said chamber, so that greater fluid pressure in the well bore below said packing means than above said packing means can act on said sleeve member surfaces to increase the compression force on said packing means, and on said hydraulically operable means surfaces to retain said slip means in outward gripping positions; and means for releasably securing said slip means and said packing means in expanded condition.

2. Apparatus for use in packing off a well bore, comprising: a body structure having a first diameter portion and a second diameter portion smaller than said first diameter portion; settable packing means mounted on said first diameter portion; means for expanding said packing means into sealing engagement with a well bore wall; normally retracted slip means on said body structure; expander means for expanding said slip means in response to downward movement relative to said slip means to set the slip means in anchoring engagement with a well bore wall, said expander means being movable by said packing expanding means; piston means sealingly and slidatbly mounted on said second diameter portion and having upper and lower transverse pressure surfaces providing an effective pressure area, said pressure area being defined with respect to its inner boundary by said second diameter portion; means for coupling said piston means in force transmitting relationship to said expander means; first passage means for feeding fluid from the well bore above said packing means to said lower pressure surface; second passage means for feeding fluid from the well bore below said packing means to said upper pressure surface, said first and second passage means cooperating with said effective pressure area for enabling the application of a downward force on the expander means suflicient to retain the slips in set position in response to greater pressure below the packing means than above the packing means; and releasable means for retaining said slip means and said packing means in both retracted and expanded conditions.

3. The apparatus of claim 2 wherein said body structure includes a mandrel, and a sleeve member carried by said mandrel, said sleeve member having an upper part providing said first diameter portion of said body structure and having a lower part providing said second diameter portion of said body structure.

4. The apparatus of claim 2 wherein said body structure includes a mandrel, and a sleeve member carried by said mandrel, said sleeve member providing said first diameter portion of said body structure, said mandrel providing said second diameter portion of said body structure.

5. A well packer apparatus comprising: a body member; a compression sleeve coupled to said body member and having an upper portion and a lower portion and an annular, downwardly facing abutment; expansible packing means mounted around said upper portion with the upper end of said packing means engaging said downwardly facing abutment; an annular, upwardly facing abutment engaging the lower end of said packing means and slidable along said upper portion and relatively toward said downwardly facing abutment to effect compression and expansion of said packing means into sealing engagement with a well bore wall; normally retracted slip means; expander means between said upwardly facing abutment and said slip means and movable downwardly relative to said slip means for expanding said slip means outwardly into gripping engagement with a well conduit wall; means responsive to downward movement of said body member and said compression sleeve relative to said slip means for moving said expander means downwardly relative of said slip means and for moving said abutments relatively toward each other; releasable locking means coacting between said body member and said slip means for securing said packing means and said slip means in expanded position; and a hydraulic piston member having upper and lower faces and coupled in force transmitting relationship to said expander means and having its inner periphery sealingly slidable on said lower portion of the compression sleeve; first passage means for feeding fluid from the well bore above said packing means to said lower face of said piston member; and second passage means for feeding fluid from the well bore below said packing means to said upper face of said piston member, said upper and lower faces providing said piston member wi h an effective pressure area on which the pressure of the fluids can act in a manner whereby greater fluid pressure in the well bore below said packing means than above said packing means forces said expander means downwardly to retain said slip means in gripping engagement with a well conduit wall, said lower portion having a smaller outer diameter than the outer diameter of said upper portion to enable said piston member to have an efie'ctive pressure area which is greater than the transverse area afforded by the size of said upwardly facing abutment.

6. The apparatus of claim 5 further including first coengageable means for preventing relative rotation between said piston member and said compression sleeve; and second coengageable means for preventing relative rotation between said piston member and said upwardly facing abutment.

7. The apparatus of claim 6 wherein said second passage means is formed in part by said first and second coengageable means.

References Cited UNITED STATES PATENTS 3,233,675 2/1966 Tamplen et al. 16612O 3,277,965 10/1966 Grimmer 166120 3,288,219 11/1966 Young et al. 166-120 3,308,886 3/1967 Evans 166134 3,338,308 8/1967 Elliston et al 166--120 3,339,637 9/1967 Holden 166-120 X 3,361,207 1/1968 Chenoweth 166l20 DAVID H. BROWN, Primary Examiner.

US. Cl. X.R. 

